Analysis of the Clean Energy 

Standard Act of 2012 

May 2012

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 ii

Contacts

This report, Analysis of the Clean Energy Standard Act of 2012, was prepared under the general guidance 

of John Conti, Assistant Administrator for Energy Analysis, J. Alan Beamon at 202/586-2025 (email, 

joseph.beamon@eia.gov), Director, Office of Electricity, Coal, Nuclear, and Renewable Analysis, and 

Robert T. Eynon at 202/586-2392 (email, robert.eynon@eia.gov), Leader, Renewable Electricity Analysis 

Team. 

Technical information concerning the content of the report may be obtained from Chris Namovicz at 

202/586-7120 (email, christopher.namovicz@eia.gov), Gwen Bredehoeft at 202/586-5847 (email, 

gwendolyn.bredehoeft@eia.gov), Jeffrey Jones at 202/586-2038 (email, jeffrey.jones@eia.gov), and 

Marie Rinkoski Spangler at 202/586-2446 (email, marie.rinkoski-spangler@eia.gov). 

Other contributors to the report include: Bill Brown, Erin Boedecker, Joel Douglas, Carrie Milton, Mark 

Schipper, Elizabeth Sendich, Robert Kennedy Smith, Kay Smith, Russ Tarver, and Peggy Wells.

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and 

analytical agency within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are 

independent of approval by any other officer or employee of the United States Government. The views 

in this report therefore should not be construed as representing those of the Department of Energy or 

other Federal agencies.
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 1

Background

This report responds to a request from Senator Jeff Bingaman, Chairman of the Senate Committee on 

Energy and Natural Resources, for an analysis of the Clean Energy Standard (CES) Act of 2012. The 

request letter and the text of the proposed legislation are provided in Appendix D. The request follows a 

previous study1

Policy Description

performed by the U.S. Energy Information Administration (EIA) in November of 2011, 

also at the request of Chairman Bingaman. In the current study, the policy is compared to EIA’s earlyrelease Reference case scenario from the Annual Energy Outlook 2012.

A CES is a policy that requires covered electricity retailers to supply a specified share of their electricity 

sales from qualifying clean energy resources. The impacts of a CES can vary substantially based on 

specification of policy details, and this analysis applies only to the specification designated in Chairman 

Bingaman’s 2012 request and the associated bill, the Clean Energy Standard Act of 20122

• All generation from existing and new wind, solar, geothermal, biomass, municipal solid waste, 

and landfill gas plants earns full credits. Hydroelectric and nuclear generation from capacity and 

uprates placed in service after 1991 earns full credits.

(BCES12), as 

described below:

• Generation from nuclear and hydroelectric capacity placed in service prior to 1992 does not 

receive any credits, but the total generation from these two sources is deducted from the 

overall requirement for credits and deducted from the sales baseline of those owning them or 

purchasing their power.

• Partial credits are earned for generation using specific technologies fueled by natural gas or coal

based on a calculated crediting factor that reflects the carbon intensity of each technology. 

More details on this crediting scheme can be found in the original BCES report1

. In addition, 

generation from combined heat and power (CHP) facilities that have an overall system efficiency 

of greater than 50 percent qualify for credits on a similar basis. However, CHP facilities that 

trade credits must also hold credits for any CHP generation used on-site.

• The Secretary of Energy will also establish additional credits for CHP facilities based on the 

greenhouse gas reductions from the facility compared to a stand-alone thermal system. This 

provision requires discretionary input not specified in the bill, and is not analyzed in this report.

• The carbon intensity of biomass generation will be determined by the Secretary of Energy based 

on a National Academy of Sciences (NAS) study specified in the legislation. For purposes of this 

report, EIA assumes that biomass generation is carbon-neutral, and biomass is thus assumed to 

earn full credit for its generation. While this assumption is consistent with assumptions made in 

the Reference case and current EIA reporting conventions, the resulting NAS report may result 

in some biomass facilities earning less-than-full CES credit for their generation.

• The BCES12 target for the share of retail electricity sales from clean energy sources starts at 24 

percent in 2015 and ultimately reaches 84 percent in 2035. Based on discussion with Chairman 

Bingaman’s staff, the analysis in this report assumes that the target remains constant after 

2035, and that the policy does not expire.

 1 See: “Analysis of Impacts of a Clean Energy Standard as requested by Chairman Bingaman”, released November 30, 2011, at 

www.eia.gov/analysis/requests/ces_bingaman/

2 See: “Clean Energy Standard Act of 2012”, at www.energy.senate.gov/public/index.cfm/files/serve?File_id=b3580f37-ec8c4698-a635-3e19f9815b9a
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 2 

• Small electricity retailers are exempt from BCES12 compliance. This exemption applies to all 

retailers with sales less than 2,000,000 megawatthours (MWh) in 2015, with the exemption 

level linearly decreasing to its terminal level of 1,000,000 MWh in annual sales for 2025 and 

beyond. 

• Covered electricity retailers may also comply by making an alternative compliance payment that 

is 3 cents per kilowatthour in 2015, increasing at an inflation-adjusted rate of 5 percent per year. 

• CES credits can be banked for use in a subsequent year. 

Results 

The BCES12 alters the projected generation mix, significantly reducing the role of coal-fired generation, 

while increasing the role of nuclear, natural gas, and non-hydropower renewable technologies. Coalfired generation decreases significantly under the BCES12, falling to 25 percent below the Reference 

case level in 2025 and 54 percent below the Reference case level in 2035. Conversely, natural gas-fired 

generation increases under the BCES12, with the greatest impact relatively early in the projection 

period, prior to significant new renewable or nuclear capacity coming online. In 2020, natural gas-fired 

generation is 13 percent above the Reference case. By 2025, this differential has fallen to 10 percent, 

and by 2035, natural gas-fired generation under the BCES12 is only 8 percent higher than in the 

Reference case. In absolute terms, most additional natural gas-fired generation occurs in the electric 

power sector; however, total combined heat and power (CHP) generation fired by natural gas does 

increase substantially due to the BCES12 provision that allows some CHP generators, to a limited extent, 

to sell BCES12 credits (see the Policy Description section). BCES12 CHP generation fired by natural gas

exceeds the Reference case by 8 percent in 2025, and by 21 percent in 2035. 

Figure 1. Total Net Electricity Generation
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 3 

Nuclear generation increases substantially under the BCES12 policy. More than 80 gigawatts of capacity 

is added by 2035, compared to less than 10 gigawatts in the Reference case, resulting in 2025 nuclear 

generation exceeding the Reference case by 16 percent and 2035 nuclear generation exceeding the 

Reference case by 62 percent. Although pre-1991 nuclear capacity does not receive credits, its 

generation is removed from the baseline of required clean energy sales, so there is an incentive not to 

retire existing units beyond those already retired in the Reference case. Furthermore, due to the 

significant number of coal-fired plant retirements–97 gigawatts by 2035 versus 33 gigawatts in the 

Reference case–there is greater need for additional baseload capacity. The relatively high credit price 

combined with the need for additional baseload capacity and CES-compliant generation all contribute to 

the significant nuclear capacity additions in the latter part of the forecast. The implications of a scenario 

in which new nuclear builds are highly constrained are discussed at the conclusion of this section.

As shown in Table A1, there is virtually no generation from plants that use carbon capture and 

sequestration (CCS) technologies under the BCES12, even though CCS technology is awarded nearly a 

full credit under the BCES12 specification. 

Figure 2. Total Non-Hydroelectric Renewable Generation

Non-hydroelectric renewable generation increases significantly under the BCES12, exceeding the 

Reference case by 42 percent in 2025, and 34 percent in 2035, with wind and biomass exhibiting the 

largest increases. Although the contribution of solar appears to be relatively unchanged, the underlying 

market structure actually shifts significantly. Projected end-use solar photovoltaic (PV) generation in 

2035 exceeds the Reference case by 71 percent under the BCES12, but electric power-sector solar PV 

falls 68 percent below the Reference case in that same year. Most of the later-term model solar PV 

capacity builds in the Reference case occur in the CAMX (California) region. Under the BCES12,

additional combined-cycle natural gas and end-use PV capacity comes online prior to when PV becomes 

cost-competitive in the region. This tends to reduce the peak load of the region, and also reduces the 
May 2012

U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 4

cost of fuels potentially displaced by the utility PV, which delays the market-based development of PV in 

the electric power sector.

Figure 3. Carbon Dioxide Emissions

Projected annual electricity sector carbon dioxide emissions decrease significantly under the BCES12, to 

20 percent below the Reference case level in 2025 and 44 percent below the Reference case level in 

2035 (Figure 3, Table A1). For context, total energy-related carbon dioxide emissions in the BCES12 case 

trail the Reference case by 8 percent in 2025, and are almost 18 percent lower than in the Reference 

case by 2035. The BCES12 level of energy-related carbon dioxide emissions in 2035 is roughly consistent 

with a 20-percent decline in emissions from a 2005 baseline.

In the early part of the forecast, average delivered natural gas prices under the BCES12 are higher than 

in the Reference case (Figure 4, Table A1), as natural gas-fired generation plays an important role in 

BCES12 compliance during the first decade of the program. Increased electric power consumption of 

natural gas results in upward pressure on prices. However, this effect attenuates toward the latter part 

of the forecast as additional non-hydro renewable and nuclear capacity comes online. 

Electricity prices, generally speaking, do not experience a significant impact until after 2020, as 

compliance with the BCES12 becomes less a matter of using natural gas and biomass at existing 

facilities, and more a matter of requiring investment in new combined cycle, renewable, and nuclear 

capacity. The projected average end-use electricity price under the BCES12 exceeds the Reference case 

by less than 4 percent in 2025, but that difference grows to 18 percent by 2035. 
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 5

Figure 4. BCES12 Impact on Average Delivered Electricity and Natural Gas Prices (BCES12 Difference 

from Reference case)

However, because electricity retailers with sales under a given level are exempt from the BCES12, 

average price impacts do not capture what may be a considerable divergence in the price impacts on 

customers of exempt and non-exempt electricity providers. Price impacts will also vary depending on 

the State-level regulatory structure in place, and on regulator discretion. These regulatory factors will 

affect or determine how credit revenues and expenditures are realized in retail electricity prices. If the 

BCES12 credits from these generators generally flow with the electricity to the small utilities they serve, 

the electricity prices to the customers of the exempt providers could actually fall because of revenue 

they earn selling the credits to non-exempt providers. Using an estimation described in Appendix B, 

results suggest that there is minimal divergence between covered and exempt utilities in the early years 

of the BCES12, but that the potential for large divergence increases as the BCES12 target increases. By 

2030, depending on the region, providers covered by the BCES12 program may pay from 3 percent to

almost 30 percent more than providers exempt from the BCES12 in the same region3

The BCES12 does not lead to large use of the alternative compliance payment (ACP) option; a relatively

small amount of ACP payments are made in the last few years of the projections, but these may arise as 

an artifact of the modeling approach.

. 

Constrained New Nuclear Capacity Scenario

As explained above, increased nuclear generation is a key compliance option in the BCES12 case. 

However, there is uncertainty about the ability of the nuclear industry to ramp up quickly even with the 

incentives that will be provided by the CES. While new nuclear capacity is once again under 

construction in the United States, it will be some time before a broad expansion could be expected. 

With these uncertainties in mind, EIA also looked at a case that assumed that no new nuclear capacity is 

 3 This assumes that baseline prices for both exempt and covered retailers are equal to regional average prices. Prices can range 

significantly from provider to provider within a region, based on a number of factors, including the size of the utility.
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U.S. Energy Information Administration   |   Analysis of the Clean Energy Standard Act of 2012 6

built, aside from planned additions in the Reference case.  Compared to the BCES12 case, natural gas

generation in 2035 is about 11 percent higher and renewable generation is about 32 percent higher in

an effort to meet the requirement with other qualifying sources.  Most of the growth in renewable

generation is projected to come from wind and solar generators.  The price for clean energy credits and

electricity prices are projected to be higher in this case, while the reduction in energy‐related carbon

dioxide emissions is smaller. With nuclear power builds limited to plants already in the pipeline, ACP

payments are more widely used than the BCES12 case by 2035.
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 7

Appendix A: Summary Table

Table A1. BCES12 and Reference Case Results

2010 2025 2035

Reference BCES12 Reference BCES12

Generation (billion kilowatthours)

Coal 1,851 1,855 1,388 1,951 901

Petroleum 37 31 21 32 18

Natural Gas 982 1,101 1,209 1,368 1,483

Nuclear 807 917 1,064 894 1,452

Conventional Hydropower 257 304 311 313 311

Non-Hydro Renewable 173 374 530 478 641

Geothermal 16 31 37 47 53

Municipal Waste 19 17 17 17 17

Wood and Other Biomass 38 146 236 178 257

Solar 6 27 28 45 46

Wind 95 153 212 190 268

Other 21 20 20 21 21

Total Generation 4,128 4,603 4,543 5,056 4,828

Capacity (gigawatts)

Coal 318 298 257 301 236

Petroleum 109 90 83 88 81

Natural Gas 350 401 386 470 430

Nuclear 101 115 134 112 184

Conventional Hydropower 78 80 82 82 82

Non-Hydro Renewable 56 93 112 119 148

Geothermal 2 4 5 6 7

Municipal Waste 4 4 4 4 4

Wood and Other Biomass 7 12 12 18 17

Solar 4 16 17 23 27

Wind 39 57 75 68 92

Other (including pumped storage) 25 25 25 25 25

Total 1,037 1,102 1,079 1,197 1,185
May 2012

U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 8

Table A1. BCES12 and Reference Case Results (continued)

2010 2025 2035

Reference BCES12 Reference BCES12

Generation by Technology (billion 

kilowatthours)

Electric Power Sector 

 Coal

 w/o Sequestration 1,831 1,883 1,508 1,952 978

 with Sequestration 0 7 7 7 7

 Oil and Natural Gas Steam 125 86 77 87 77

 Combined Cycle

 w/o Sequestration 752 877 974 1,087 1,150

 with Sequestration 0 0 0 3 0

 Combustion Turbine/Diesel

 Advanced 0 1 0 2 0

 Conventional 66 35 31 34 31

 Nuclear Power 807 917 1,064 894 1,452

 Other 390 522 589 599 665

End-Use 

 Coal 20 46 46 63 63

 Petroleum 3 2 2 2 2

 Natural Gas 84 121 140 174 237

 Other Gaseous Fuels 11 15 15 15 15

 Renewable Sources 35 87 89 134 148

 Other 4 3 3 3 3

Total 4,128 4,603 4,543 5,056 4,828

Prices (2010 cents/kWh)

Credit Price 3.30 7.96

Average End-Use Electricity Price 9.78 9.29 9.65 9.54 11.29

Residential 11.50 11.02 11.48 11.08 12.77

Commercial 10.14 9.47 9.74 9.55 11.30

Industrial 6.70 6.43 6.70 6.82 8.54

Average Delivered Natural Gas Price (2010 

dollars/Mcf) 7.33 8.03 8.06 9.40 9.47

Expenditures (billion 2010 dollars)

Total Electricity Expenditures 367 385 394 429 481

Residential Electricity Expenditures 167 171 177 193 213

Household Electricity Expenditures (2010 

Dollars/Household) 1460 1291 1332 1326 1465

Total Natural Gas Expenditures 163 186 190 228 234

Electricity Sector Natural Gas 

Expenditures 39 45 48 65 67

Non-Electricity Sector Natural Gas 

Expenditures 124 141 142 164 167
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 9

Table A1. BCES12 and Reference Case Results (continued)

2010 2025 2035

Reference BCES12 Reference BCES12

CES Compliance

Alternative Compliance Payment (billion 

2010 dollars) 0 36

Credits Required (percent of sales) 34 54

Credits Achieved (percent of sales) 31 43

Generation Achieved (percent of sales) 34 43

Total Electricity Sales (billion kilowatthours) 3,730 4,121 4,067 4,467 4,234

Electric Power Sector Emissions

Sulfur Dioxide (million tons) 5.1 2.8 2.6 2.8 1.7

Nitrogen Oxide (million tons) 2.1 2.0 1.7 2.0 1.1

Mercury (tons) 35 24 19 24 11

Carbon Dioxide (million metric tons CO2) 2,271 2,234 1,789 2,383 1,346

Macroeconomic

GDP (billion 2005 dollars) 13,088 19,176 19,135 24,639 24,508

Per Capita GDP (thousand 2005 

dollars/person) 42.1 53.6 53.4 63.2 62.8

Employment, Non-Farm (million) 129.8 153.3 153.3 166.7 166.2

Employment, Manufacturing (million) 11.5 11.4 11.4 9.1 9.0
May 2012

U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 10

Appendix B: Estimating Price Impacts of the BCES12 Small 

Retailer Exemption

The CES policy proposal analyzed in this paper, as outlined in the letter and draft legislation provided in 

Appendix D, exempts small electricity retailers. Small electricity retailers are defined as those with sales 

less than 2,000,000 megawatthours (MWh) in 2015, with the exemption level decreasing linearly to 

1,000,000 MWh in 2025 and beyond. EIA is not able to disaggregate the price impacts of exempt small 

retailers from those of larger covered retailers within the National Energy Modeling System (NEMS). 

Given the exemption, there is likely to be a considerable divergence in the price impacts for customers 

of exempt and non-exempt electricity providers. Using historical data and assuming that small retailer 

sales grow at the same rate as total sales in a region, we can approximate the extent of the regional 

differences in the proportions of exempt and non-exempt retail electricity sales (Table B1). 

Table B1. Exempt Retailer Share of Total Sales by Electricity Market Module (EMM) Region4

Region 2015 2020 2025 2030 2035

Texas Regional Entity (ERCT) 0.15 0.11 0.08 0.08 0.08

Florida Reliability Coordinating Council (FRCC) 0.07 0.06 0.04 0.04 0.04

Midwest Reliability Organization / East (MROE) 0.32 0.26 0.25 0.25 0.25

Midwest Reliability Organization / West (MROW) 0.34 0.32 0.28 0.28 0.28

NPCC / Northeast (NEWE) 0.15 0.13 0.12 0.12 0.12

NPCC / NYC-Westchester (NYCW) 0.07 0.05 0.02 0.02 0.02

NPCC / Long Island (NYLI) 0.03 0.03 0.03 0.03 0.03

NPCC / Upstate New York (NYUP) 0.15 0.14 0.14 0.14 0.14

Reliability First Corporation / East (RFCE) 0.05 0.04 0.03 0.03 0.03

Reliability First Corporation / Michigan (RFCM) 0.09 0.09 0.06 0.05 0.05

Reliability First Corporation / West (RFCW) 0.1 0.1 0.09 0.09 0.09

SERC / Delta (SRDA) 0.14 0.13 0.08 0.08 0.08

SERC / Gateway (SRGW) 0.3 0.28 0.24 0.24 0.23

SERC / Southeastern (SRSE) 0.22 0.18 0.13 0.12 0.12

SERC / Central (SRCE) 0.39 0.34 0.23 0.22 0.21

SERC / Virginia-Carolina (SRVC) 0.18 0.16 0.1 0.09 0.08

Southwest Power Pool / North (SPNO) 0.19 0.19 0.15 0.15 0.15

Southwest Power Pool / South (SPSO) 0.28 0.25 0.2 0.19 0.19

WECC / Southwest (AZNM) 0.11 0.09 0.07 0.07 0.07

WECC / California (CAMX) 0.06 0.05 0.02 0.02 0.02

WECC / Northwest Power Pool Area (NWPP) 0.21 0.19 0.15 0.14 0.13

WECC / Rockies (RMPA) 0.3 0.27 0.17 0.16 0.15

Note: Darker shades indicate a higher share of exempt retail sales. Source: U.S. Energy Information 

Administration, based on National Energy Modeling System, run ref2012.d121011b, and Form EIA-861

As shown, these regional differences are pronounced and persistent throughout the projections. It 

should also be noted that these estimates assume that larger retail utilities do not take steps that might 

increase the number of exempt small retailers when faced with the CES requirement. The price paid by a 

 4 See Appendix C for a map of EMM regions
May 2012

U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 11

customer of a covered (non-exempt or large) provider will include a certain amount of compliance cost. 

The price paid by a customer of an exempt provider will not. 

While EIA cannot determine an actual projection for differences in electricity price impacts between 

exempt and covered retailers, we can get a general sense of the potential magnitude of these 

differences attributable to the CES by apportioning the national CES credit expenditures in any given 

year to each region based on that region’s share of the national covered load, excluding exempt retailers 

and excluded nuclear and conventional hydropower sales. By dividing this allocation by the sales from 

the covered retailers in the region, EIA can estimate how much (per kWh) CES compliance is costing 

covered retailers, which, under some circumstances, would represent the compliance component of the 

average retail price for those retailers. To figure out the price to the exempt retailers, shown for 

selected regions in Figure B1, subtract the regional share of CES expenditures from the total regional 

electricity expenditures, then divide by total sales. This calculation yields a value for the underlying cost 

of electricity excluding the purchase of any CES credits, which, under some circumstances, would 

represent the price paid by the exempt retailers. The price paid by the covered retailers is the 

underlying electricity price plus the compliance component estimated previously. 

Figure B1. Regional Delivered Electricity Price Comparison for Selected Regions

This approach implicitly assumes that electricity retailers purchase the CES credits. Generation is 

implicitly assumed to come from pure-play generators (that is, independent power producers, 

deregulated utility subsidiaries, or other generators that don’t directly serve retail load). The retail price 

estimated in the model already accounts for any price reductions that result from the sale of credits, 

and this approach assumes it to be retained by the generators. In a region that relies primarily on 

market-based pricing mechanisms, this assumption seems reasonable. In a region that relies primarily 

on cost-of-service regulation as a pricing mechanism, this approach would be consistent with a regulator 

that allowed or required retail utilities to obtain generation, especially CES-compliant generation, from 
May 2012

U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 12

non-retail generators. For vertically integrated electricity utilities that are generating substantial 

amounts of compliant generation “in house”, this approach would not accurately account for the price 

offsets that came from selling CES credits. Currently, somewhat more than half of the CES-compliant 

capacity is owned by non-utility generators, and EIA assumes that all new generation comes from these 

sources, rather than from capacity owned by the retail electricity sellers. However, it is important to 

note that regulatory practice may change in unexpected ways in the face of a significant new Federal 

policy, such as the one examined here. This approach does not account for any underlying price 

differences between exempt and covered retailers in any given region.

When applying this approach, EIA finds that regions with a lower average electricity price would tend to 

see a greater disparity in price between the exempt and covered retailers. This reflects a situation in 

which total compliance cost will tend to be a larger portion of total electricity costs for the covered

retailers.

In addition, EIA finds that the excluded nuclear/hydropower generation in a region is a significant factor 

affecting intra-regional price disparity. Excluded generation tends to depress overall regional 

compliance costs, so regions with more excluded generation tend to have lower costs. This may be 

somewhat offset if the exempt retailer share of sales is particularly large in a region, as compliance costs 

will be spread over fewer units of sales. However, it is difficult to disentangle the relationship here, as 

some of the regions with the highest shares of excluded generation also have some of the largest shares 

of small retailers (NWPP5

 5 See Appendix C for a map of EMM regions

, SRCE, SRGW) and vice versa (ERCT, MROE, RFCM). 
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 13

Figure B2. Ratio of Estimated Price at Covered Retailers to Estimated Price at Exempt Retailers, by 

Year and Region

In the early years, when the CES target is low, there is little covered/exempt disparity in any of the 

regions; generally we’d expect the costs of covered retailers to be 1 percent to 15 percent above the 

cost of exempt small retailers in the same region in 2020 (Figure B2). As the target increases, the 

exempt retail load decreases, and the electricity price increases, the spread in the credit-inclusive cost of 

generation between the covered and exempt retailers becomes quite pronounced. By 2030, we’d 

expect the credit-inclusive cost of generation for covered retailers to be about 3 percent to 30 percent

above the costs of exempt small retailers in the same region. After the price cap is reached, in regions 

with the largest disparity, covered retailers are paying almost twice as much for wholesale electricity as 

exempt retailers in the same region. Upstate New York (NYUP) is still a low-disparity outlier at this 

point, with only a 5 percent difference, and in the next lowest disparity regions (NYCW and NEWE),

covered retailers are paying about 25 percent to 30 percent more than the exempt retailers.

1

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

1.9

2

2015 2020 2025 2030 2035

ERCT

FRCC

MROE

MROW

NEWE

NYCW

NYLI

NYUP

RFCE

RFCM

RFCW

SRDA

SRGW

SRSE

SRCE

SRVC

SPNO

SPSO

AZNM

CAMX

NWPP

RMPA

Source: U.S. Energy Information Administration, based on National Energy Modeling System, runs 

ref2012.d121011b and bing12ichp.d042312b and Form EIA-861.
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 14

Appendix C: Map of NEMS Electricity Market Module Regions

1 Texas Regional Entity (ERCT) 12 SERC / Delta (SRDA)

2 Florida Reliability Coordinating Council (FRCC) 13 SERC / Gateway (SRGW)

3 Midwest Reliability Organization / East (MROE) 14 SERC / Southeastern (SRSE)

4 Midwest Reliability Organization / West (MROW) 15 SERC / Central (SRCE)

5 NPCC / Northeast (NEWE) 16 SERC / Virginia-Carolina (SRVC)

6 NPCC / NYC-Westchester (NYCW) 17 Southwest Power Pool / North (SPNO)

7 NPCC / Long Island (NYLI) 18 Southwest Power Pool / South (SPSO)

8 NPCC / Upstate New York (NYUP) 19 WECC / Southwest (AZNM)

9 Reliability First Corporation / East (RFCE) 20 WECC / California (CAMX)

10 Reliability First Corporation / Michigan (RFCM) 21 WECC / Northwest Power Pool Area (NWPP)

11 Reliability First Corporation / West (RFCW) 22 WECC / Rockies (RMPA)
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U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 15

Appendix D: Request Letter and Bill
May 2012

U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 16
May 2012

U.S. Energy Information Administration | Analysis of the Clean Energy Standard Act of 2012 17
II 

112TH CONGRESS 

2D SESSION S. 2146 

To amend the Public Utility Regulatory Policies Act of 1978 to create 

a market-oriented standard for clean electric energy generation, and 

for other purposes. 

IN THE SENATE OF THE UNITED STATES 

MARCH 1, 2012 

Mr. BINGAMAN (for himself, Mr. WYDEN, Mr. SANDERS, Mr. UDALL of Colorado, Mr. FRANKEN, Mr. COONS, Mr. KERRY, Mr. WHITEHOUSE, and 

Mr. UDALL of New Mexico) introduced the following bill; which was read 

twice and referred to the Committee on Energy and Natural Resources 

A BILL 

To amend the Public Utility Regulatory Policies Act of 1978 

to create a market-oriented standard for clean electric 

energy generation, and for other purposes. 

1 Be it enacted by the Senate and House of Representa2 tives of the United States of America in Congress assembled, 

3 SECTION 1. SHORT TITLE. 

4 This Act may be cited as the ‘‘Clean Energy Stand5 ard Act of 2012’’. 


smartinez on DSK6TPTVN1PROD with BILLS
2 

•S 2146 IS

1 SEC. 2. FEDERAL CLEAN ENERGY STANDARD. 

2 Title VI of the Public Utility Regulatory Policies Act 

3 of 1978 (16 U.S.C. 2601 et seq.) is amended by adding 

4 at the end the following: 

5 ‘‘SEC. 610. FEDERAL CLEAN ENERGY STANDARD. 

6 ‘‘(a) PURPOSE.—The purpose of this section is to cre7 ate a market-oriented standard for electric energy genera8 tion that stimulates clean energy innovation and promotes 

9 a diverse set of low- and zero-carbon generation solutions 

10 in the United States at the lowest incremental cost to elec11 tric consumers. 

12 ‘‘(b) DEFINITIONS.—In this section: 

13 ‘‘(1) CLEAN ENERGY.—The term ‘clean energy’ 

14 means electric energy that is generated— 

15 ‘‘(A) at a facility placed in service after 

16 December 31, 1991, using— 

17 ‘‘(i) renewable energy; 

18 ‘‘(ii) qualified renewable biomass; 

19 ‘‘(iii) natural gas; 

20 ‘‘(iv) hydropower; 

21 ‘‘(v) nuclear power; or 

22 ‘‘(vi) qualified waste-to-energy; 

23 ‘‘(B) at a facility placed in service after 

24 the date of enactment of this section, using— 

25 ‘‘(i) qualified combined heat and 

26 power; or 


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1 ‘‘(ii) a source of energy, other than 

2 biomass, with lower annual carbon inten3 sity than 0.82 metric tons of carbon diox4 ide equivalent per megawatt-hour; 

5 ‘‘(C) as a result of qualified efficiency im6 provements or capacity additions; or 

7 ‘‘(D) at a facility that captures carbon di8 oxide and prevents the release of the carbon di9 oxide into the atmosphere. 

10 ‘‘(2) NATURAL GAS.— 

11 ‘‘(A) INCLUSION.—The term ‘natural gas’ 

12 includes coal mine methane. 

13 ‘‘(B) EXCLUSIONS.—The term ‘natural 

14 gas’ excludes landfill methane and biogas. 

15 ‘‘(3) QUALIFIED COMBINED HEAT AND

16 POWER.— 

17 ‘‘(A) IN GENERAL.—The term ‘qualified 

18 combined heat and power’ means a system 

19 that— 

20 ‘‘(i) uses the same energy source for 

21 the simultaneous or sequential generation 

22 of electrical energy and thermal energy; 

23 ‘‘(ii) produces at least— 


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1 ‘‘(I) 20 percent of the useful en2 ergy of the system in the form of elec3 tricity; and 

4 ‘‘(II) 20 percent of the useful en5 ergy in the form of useful thermal en6 ergy; 

7 ‘‘(iii) to the extent the system uses 

8 biomass, uses only qualified renewable bio9 mass; and 

10 ‘‘(iv) operates with an energy effi11 ciency percentage that is greater than 50 

12 percent. 

13 ‘‘(B) DETERMINATION OF ENERGY EFFI14 CIENCY.—For purposes of subparagraph (A), 

15 the energy efficiency percentage of a combined 

16 heat and power system shall be determined in 

17 accordance with section 48(c)(3)(C)(i) of the 

18 Internal Revenue Code of 1986. 

19 ‘‘(4) QUALIFIED EFFICIENCY IMPROVEMENTS

20 OR CAPACITY ADDITIONS.— 

21 ‘‘(A) IN GENERAL.—Subject to subpara22 graphs (B) and (C), the term ‘qualified effi23 ciency improvements or capacity additions’ 

24 means efficiency improvements or capacity ad25 ditions made after December 31, 1991, to— 


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1 ‘‘(i) a nuclear facility placed in service 

2 on or before December 31, 1991; or 

3 ‘‘(ii) a hydropower facility placed in 

4 service on or before December 31, 1991. 

5 ‘‘(B) EXCLUSION.—The term ‘qualified ef6 ficiency improvements or capacity additions’ 

7 does not include additional electric energy gen8 erated as a result of operational changes not di9 rectly associated with efficiency improvements 

10 or capacity additions. 

11 ‘‘(C) MEASUREMENT AND CERTIFI12 CATION.—In the case of hydropower, efficiency 

13 improvements and capacity additions under this 

14 paragraph shall be— 

15 ‘‘(i) measured on the basis of the 

16 same water flow information that is used 

17 to determine the historic average annual 

18 generation for the applicable hydroelectric 

19 facility; and 

20 ‘‘(ii) certified by the Secretary or the 

21 Commission. 

22 ‘‘(5) QUALIFIED RENEWABLE BIOMASS.—The 

23 term ‘qualified renewable biomass’ means renewable 

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1 position, structure, and processes of ecosystems, in2 cluding the diversity of plant and animal commu3 nities, water quality, and the productive capacity of 

4 soil and the ecological systems. 

5 ‘‘(6) QUALIFIED WASTE-TO-ENERGY.—The 

6 term ‘qualified waste-to-energy’ means energy pro7 duced— 

8 ‘‘(A) from the combustion of— 

9 ‘‘(i) post-recycled municipal solid 

10 waste; 

11 ‘‘(ii) gas produced from the gasifi12 cation or pyrolization of post-recycled mu13 nicipal solid waste; 

14 ‘‘(iii) biogas; 

15 ‘‘(iv) landfill methane; 

16 ‘‘(v) animal waste or animal byprod17 ucts; or 

18 ‘‘(vi) wood, paper products that are 

19 not commonly recyclable, and vegetation 

20 (including trees and trimmings, yard 

21 waste, pallets, railroad ties, crates, and 

22 solid-wood manufacturing and construction 

23 debris), if diverted from or separated from 

24 other waste out of a municipal waste 

25 stream; and 


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1 ‘‘(B) at a facility that the Commission has 

2 certified, on an annual basis, is in compliance 

3 with all applicable Federal and State environ4 mental permits, including— 

5 ‘‘(i) in the case of a facility that com6 mences operation before the date of enact7 ment of this section, compliance with emis8 sion standards under sections 112 and 129 

9 of the Clean Air Act (42 U.S.C. 7412, 

10 7429) that apply as of the date of enact11 ment of this section to new facilities within 

12 the applicable source category; and 

13 ‘‘(ii) in the case of a facility that pro14 duces electric energy from the combustion, 

15 pyrolization, or gasification of municipal 

16 solid waste, certification that each local 

17 government unit from which the waste 

18 originates operates, participates in the op19 eration of, contracts for, or otherwise pro20 vides for recycling services for residents of 

21 the local government unit. 

22 ‘‘(7) RENEWABLE ENERGY.—The term ‘renew23 able energy’ means solar, wind, ocean, current, wave, 

24 tidal, or geothermal energy. 

25 ‘‘(c) CLEAN ENERGY REQUIREMENT.— 


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1 ‘‘(1) IN GENERAL.—Effective beginning in cal2 endar year 2015, each electric utility that sells elec3 tric energy to electric consumers in a State shall ob4 tain a percentage of the electric energy the electric 

5 utility sells to electric consumers during a calendar 

6 year from clean energy. 

7 ‘‘(2) PERCENTAGE REQUIRED.—The percentage 

8 of electric energy sold during a calendar year that 

9 is required to be clean energy under paragraph (1) 

10 shall be determined in accordance with the following 

11 table: 

‘‘Calendar year 

Minimum 

annual 

percentage 

2015 ................................................................................................ 24

2016 ................................................................................................ 27

2017 ................................................................................................ 30

2018 ................................................................................................ 33

2019 ................................................................................................ 36

2020 ................................................................................................ 39

2021 ................................................................................................ 42

2022 ................................................................................................ 45

2023 ................................................................................................ 48

2024 ................................................................................................ 51

2025 ................................................................................................ 54

2026 ................................................................................................ 57

2027 ................................................................................................ 60

2028 ................................................................................................ 63

2029 ................................................................................................ 66

2030 ................................................................................................ 69

2031 ................................................................................................ 72

2032 ................................................................................................ 75

2033 ................................................................................................ 78

2034 ................................................................................................ 81

2035 ................................................................................................ 84. 

12 ‘‘(3) DEDUCTION FOR ELECTRIC ENERGY GEN13 ERATED FROM HYDROPOWER OR NUCLEAR


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1 POWER.—An electric utility that sells electric energy 

2 to electric consumers from a facility placed in service 

3 in the United States on or before December 31, 

4 1991, using hydropower or nuclear power may de5 duct the quantity of the electric energy from the 

6 quantity to which the percentage in paragraph (2) 

7 applies. 

8 ‘‘(d) MEANS OF COMPLIANCE.—An electric utility 

9 shall meet the requirements of subsection (c) by— 

10 ‘‘(1) submitting to the Secretary clean energy 

11 credits issued under subsection (e); 

12 ‘‘(2) making alternative compliance payments of 

13 3 cents per kilowatt hour in accordance with sub14 section (i); or 

15 ‘‘(3) taking a combination of actions described 

16 in paragraphs (1) and (2). 

17 ‘‘(e) FEDERAL CLEAN ENERGY TRADING PRO18 GRAM.— 

19 ‘‘(1) ESTABLISHMENT.—Not later than 180 

20 days after the date of enactment of this section, the 

21 Secretary shall establish a Federal clean energy 

22 credit trading program under which electric utilities 

23 may submit to the Secretary clean energy credits to 

24 certify compliance by the electric utilities with sub25 section (c). 


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1 ‘‘(2) CLEAN ENERGY CREDITS.—Except as pro2 vided in paragraph (3)(B), the Secretary shall issue 

3 to each generator of electric energy a quantity of 

4 clean energy credits determined in accordance with 

5 subsections (f) and (g). 

6 ‘‘(3) ADMINISTRATION.—In carrying out the 

7 program under this subsection, the Secretary shall 

8 ensure that— 

9 ‘‘(A) a clean energy credit shall be used 

10 only once for purposes of compliance with this 

11 section; and 

12 ‘‘(B) a clean energy credit issued for clean 

13 energy generated and sold for resale under a 

14 contract in effect on the date of enactment of 

15 this section shall be issued to the purchasing 

16 electric utility, unless otherwise provided by the 

17 contract. 

18 ‘‘(4) DELEGATION OF MARKET FUNCTION.— 

19 ‘‘(A) IN GENERAL.—In carrying out the 

20 program under this subsection, the Secretary 

21 may delegate— 

22 ‘‘(i) to 1 or more appropriate market23 making entities, the administration of a 

24 national clean energy credit market for 

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1 tional market for the sale or trade of clean 

2 energy credits; and 

3 ‘‘(ii) to appropriate entities, the track4 ing of dispatch of clean generation. 

5 ‘‘(B) ADMINISTRATION.—In making a del6 egation under subparagraph (A)(ii), the Sec7 retary shall ensure that the tracking and re8 porting of information concerning the dispatch 

9 of clean generation is transparent, verifiable, 

10 and independent of any generation or load in11 terests subject to an obligation under this sec12 tion. 

13 ‘‘(5) BANKING OF CLEAN ENERGY CREDITS.— 

14 Clean energy credits to be used for compliance pur15 poses under subsection (c) shall be valid for the year 

16 in which the clean energy credits are issued or in 

17 any subsequent calendar year. 

18 ‘‘(f) DETERMINATION OF QUANTITY OF CREDIT.— 

19 ‘‘(1) IN GENERAL.—Except as otherwise pro20 vided in this subsection, the quantity of clean energy 

21 credits issued to each electric utility generating elec22 tric energy in the United States from clean energy 

23 shall be equal to the product of— 


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1 ‘‘(A) for each generator owned by a utility, 

2 the number of megawatt-hours of electric en3 ergy sold from that generator by the utility; and 

4 ‘‘(B) the difference between— 

5 ‘‘(i) 1.0; and 

6 ‘‘(ii) the quotient obtained by divid7 ing— 

8 ‘‘(I) the annual carbon intensity 

9 of the generator, as determined in ac10 cordance with subsection (g), ex11 pressed in metric tons per megawatt12 hour; by 

13 ‘‘(II) 0.82. 

14 ‘‘(2) NEGATIVE CREDITS.—Notwithstanding 

15 any other provision of this subsection, the Secretary 

16 shall not issue a negative quantity of clean energy 

17 credits to any generator. 

18 ‘‘(3) QUALIFIED COMBINED HEAT AND

19 POWER.— 

20 ‘‘(A) IN GENERAL.—The quantity of clean 

21 energy credits issued to an owner of a qualified 

22 combined heat and power system in the United 

23 States shall be equal to the difference be24 tween— 


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1 ‘‘(i) the product obtained by multi2 plying— 

3 ‘‘(I) the number of megawatt4 hours of electric energy generated by 

5 the system; and 

6 ‘‘(II) the difference between— 

7 ‘‘(aa) 1.0; and 

8 ‘‘(bb) the quotient obtained 

9 by dividing— 

10 ‘‘(AA) the annual car11 bon intensity of the gener12 ator, as determined in ac13 cordance with subsection 

14 (g), expressed in metric tons 

15 per megawatt-hour; by 

16 ‘‘(BB) 0.82; and 

17 ‘‘(ii) the product obtained by multi18 plying— 

19 ‘‘(I) the number of megawatt20 hours of electric energy generated by 

21 the system that are consumed onsite 

22 by the facility; and 

23 ‘‘(II) the annual target for elec24 tric energy sold during a calendar 


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1 year that is required to be clean en2 ergy under subsection (c)(2). 

3 ‘‘(B) ADDITIONAL CREDITS.—In addition 

4 to credits issued under subparagraph (A), the 

5 Secretary shall award clean energy credits to an 

6 owner of a qualified heat and power system in 

7 the United States for greenhouse gas emissions 

8 avoided as a result of the use of a qualified 

9 combined heat and power system, rather than a 

10 separate thermal source, to meet onsite thermal 

11 needs. 

12 ‘‘(4) QUALIFIED WASTE-TO-ENERGY.—The 

13 quantity of clean energy credits issued to an electric 

14 utility generating electric energy in the United 

15 States from a qualified waste-to-energy facility shall 

16 be equal to the product obtained by multiplying— 

17 ‘‘(A) the number of megawatt-hours of 

18 electric energy generated by the facility and 

19 sold by the utility; and 

20 ‘‘(B) 1.0. 

21 ‘‘(g) DETERMINATION OF ANNUAL CARBON INTEN22 SITY OF GENERATING FACILITIES.— 

23 ‘‘(1) IN GENERAL.—For purposes of deter24 mining the quantity of credits under subsection (f), 

25 except as provided in paragraph (2), the Secretary 


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1 shall determine the annual carbon intensity of each 

2 generator by dividing— 

3 ‘‘(A) the net annual carbon dioxide equiva4 lent emissions of the generator; by 

5 ‘‘(B) the annual quantity of electricity gen6 erated by the generator. 

7 ‘‘(2) BIOMASS.—The Secretary shall— 

8 ‘‘(A) not later than 180 days after the date 

9 of enactment of this section, issue interim regu10 lations for determining the carbon intensity 

11 based on an initial consideration of the issues 

12 to be reported on under subparagraph (B); 

13 ‘‘(B) not later than 180 days after the 

14 date of enactment of this section, enter into an 

15 agreement with the National Academy of 

16 Sciences under which the Academy shall— 

17 ‘‘(i) evaluate models and methodolo18 gies for quantifying net changes in green19 house gas emissions associated with gener20 ating electric energy from each significant 

21 source of qualified renewable biomass, in22 cluding evaluation of additional sequestra23 tion or emissions associated with changes 

24 in land use by the production of the bio25 mass; and 


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1 ‘‘(ii) not later than 1 year after the 

2 date of enactment of this section, publish 

3 a report that includes— 

4 ‘‘(I) a description of the evalua5 tion required by clause (i); and 

6 ‘‘(II) recommendations for deter7 mining the carbon intensity of electric 

8 energy generated from qualified re9 newable biomass under this section; 

10 and 

11 ‘‘(C) not later than 180 days after the 

12 publication of the report under subparagraph 

13 (B)(ii), issue regulations for determining the 

14 carbon intensity of electric energy generated 

15 from qualified renewable biomass that take into 

16 account the report. 

17 ‘‘(3) CONSULTATION.—The Secretary shall con18 sult with— 

19 ‘‘(A) the Administrator of the Environ20 mental Protection Agency in determining the 

21 annual carbon intensity of generating facilities 

22 under paragraph (1); and 

23 ‘‘(B) the Administrator of the Environ24 mental Protection Agency, the Secretary of the 

25 Interior, and the Secretary of Agriculture in 


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1 issuing regulations for determining the carbon 

2 intensity of electric energy generated by bio3 mass under paragraph (2)(C). 

4 ‘‘(h) CIVIL PENALTIES.— 

5 ‘‘(1) IN GENERAL.—Subject to paragraph (2), 

6 an electric utility that fails to meet the requirements 

7 of this section shall be subject to a civil penalty in 

8 an amount equal to the product obtained by multi9 plying— 

10 ‘‘(A) the number of kilowatt-hours of elec11 tric energy sold by the utility to electric con12 sumers in violation of subsection (c); and 

13 ‘‘(B) 200 percent of the value of the alter14 native compliance payment, as adjusted under 

15 subsection (m). 

16 ‘‘(2) WAIVERS AND MITIGATION.— 

17 ‘‘(A) FORCE MAJEURE.—The Secretary 

18 may mitigate or waive a civil penalty under this 

19 subsection if the electric utility was unable to 

20 comply with an applicable requirement of this 

21 section for reasons outside of the reasonable 

22 control of the utility. 

23 ‘‘(B) REDUCTION FOR STATE PEN24 ALTIES.—The Secretary shall reduce the 

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1 graph (1) by the amount paid by the electric 

2 utility to a State for failure to comply with the 

3 requirement of a State renewable energy pro4 gram, if the State requirement is more strin5 gent than the applicable requirement of this 

6 section. 

7 ‘‘(3) PROCEDURE FOR ASSESSING PENALTY.— 

8 The Secretary shall assess a civil penalty under this 

9 subsection in accordance with section 333(d) of the 

10 Energy Policy and Conservation Act (42 U.S.C. 

11 6303(d)). 

12 ‘‘(i) ALTERNATIVE COMPLIANCE PAYMENTS.—An 

13 electric utility may satisfy the requirements of subsection 

14 (c), in whole or in part, by submitting in lieu of a clean 

15 energy credit issued under this section a payment equal 

16 to the amount required under subsection (d)(2), in accord17 ance with such regulations as the Secretary may promul18 gate. 

19 ‘‘(j) STATE ENERGY EFFICIENCY FUNDING PRO20 GRAM.— 

21 ‘‘(1) ESTABLISHMENT.—Not later than Decem22 ber 31, 2015, the Secretary shall establish a State 

23 energy efficiency funding program. 

24 ‘‘(2) FUNDING.—All funds collected by the Sec25 retary as alternative compliance payments under 


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1 subsection (i), or as civil penalties under subsection 

2 (h), shall be used solely to carry out the program 

3 under this subsection. 

4 ‘‘(3) DISTRIBUTION TO STATES.— 

5 ‘‘(A) IN GENERAL.—An amount equal to 

6 75 percent of the funds described in paragraph 

7 (2) shall be used by the Secretary, without fur8 ther appropriation or fiscal year limitation, to 

9 provide funds to States for the implementation 

10 of State energy efficiency plans under section 

11 362 of the Energy Policy and Conservation Act 

12 (42 U.S.C. 6322), in accordance with the pro13 portion of those amounts collected by the Sec14 retary from each State. 

15 ‘‘(B) ACTION BY STATES.—A State that 

16 receives funds under this paragraph shall main17 tain such records and evidence of compliance as 

18 the Secretary may require. 

19 ‘‘(4) GUIDELINES AND CRITERIA.—The Sec20 retary may issue such additional guidelines and cri21 teria for the program under this subsection as the 

22 Secretary determines to be appropriate. 

23 ‘‘(k) EXEMPTIONS.— 

24 ‘‘(1) IN GENERAL.—This section shall not apply 

25 during any calendar year to an electric utility that 


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1 sold less than the applicable quantity described in 

2 paragraph (2) of megawatt-hours of electric energy 

3 to electric consumers during the preceding calendar 

4 year. 

5 ‘‘(2) APPLICABLE QUANTITY.—For purposes of 

6 paragraph (1), the applicable quantity is— 

7 ‘‘(A) in the case of calendar year 2015, 

8 2,000,000; 

9 ‘‘(B) in the case of calendar year 2016, 

10 1,900,000; 

11 ‘‘(C) in the case of calendar year 2017, 

12 1,800,000; 

13 ‘‘(D) in the case of calendar year 2018, 

14 1,700,000; 

15 ‘‘(E) in the case of calendar year 2019, 

16 1,600,000; 

17 ‘‘(F) in the case of calendar year 2020, 

18 1,500,000; 

19 ‘‘(G) in the case of calendar year 2021, 

20 1,400,000; 

21 ‘‘(H) in the case of calendar year 2022, 

22 1,300,000; 

23 ‘‘(I) in the case of calendar year 2023, 

24 1,200,000; 


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1 ‘‘(J) in the case of calendar year 2024, 

2 1,100,000; and 

3 ‘‘(K) in the case of calendar year 2025 and 

4 each calendar year thereafter, 1,000,000. 

5 ‘‘(3) CALCULATION OF ELECTRIC ENERGY

6 SOLD.— 

7 ‘‘(A) DEFINITIONS.—In this subsection, 

8 the terms ‘affiliate’ and ‘associate company’ 

9 have the meanings given the terms in section 

10 1262 of the Energy Policy Act of 2005 (42 

11 U.S.C. 16451). 

12 ‘‘(B) INCLUSION.—For purposes of calcu13 lating the quantity of electric energy sold by an 

14 electric utility under this subsection, the quan15 tity of electric energy sold by an affiliate of the 

16 electric utility or an associate company shall be 

17 treated as sold by the electric utility. 

18 ‘‘(l) STATE PROGRAMS.— 

19 ‘‘(1) SAVINGS PROVISION.— 

20 ‘‘(A) IN GENERAL.—Subject to paragraph 

21 (2), nothing in this section affects the authority 

22 of a State or a political subdivision of a State 

23 to adopt or enforce any law or regulation relat24 ing to— 

25 ‘‘(i) clean or renewable energy; or 


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1 ‘‘(ii) the regulation of an electric util2 ity. 

3 ‘‘(B) FEDERAL LAW.—No law or regula4 tion of a State or a political subdivision of a 

5 State may relieve an electric utility from com6 pliance with an applicable requirement of this 

7 section. 

8 ‘‘(2) COORDINATION.—The Secretary, in con9 sultation with States that have clean and renewable 

10 energy programs in effect, shall facilitate, to the 

11 maximum extent practicable, coordination between 

12 the Federal clean energy program under this section 

13 and the relevant State clean and renewable energy 

14 programs. 

15 ‘‘(m) ADJUSTMENT OF ALTERNATIVE COMPLIANCE

16 PAYMENT.—Not later than December 31, 2016, and an17 nually thereafter, the Secretary shall— 

18 ‘‘(1) increase by 5 percent the rate of the alter19 native compliance payment under subsection (d)(2); 

20 and 

21 ‘‘(2) additionally adjust that rate for inflation, 

22 as the Secretary determines to be necessary. 

23 ‘‘(n) REPORT ON CLEAN ENERGY RESOURCES THAT

24 DO NOT GENERATE ELECTRIC ENERGY.— 


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1 ‘‘(1) IN GENERAL.—Not later than 3 years 

2 after the date of enactment of this section, the Sec3 retary shall submit to Congress a report examining 

4 mechanisms to supplement the standard under this 

5 section by addressing clean energy resources that do 

6 not generate electric energy but that may substan7 tially reduce electric energy loads, including energy 

8 efficiency, biomass converted to thermal energy, geo9 thermal energy collected using heat pumps, thermal 

10 energy delivered through district heating systems, 

11 and waste heat used as industrial process heat. 

12 ‘‘(2) POTENTIAL INTEGRATION.—The report 

13 under paragraph (1) shall examine the benefits and 

14 challenges of integrating the additional clean energy 

15 resources into the standard established by this sec16 tion, including— 

17 ‘‘(A) the extent to which such an integra18 tion would achieve the purposes of this section; 

19 ‘‘(B) the manner in which a baseline de20 scribing the use of the resources could be devel21 oped that would ensure that only incremental 

22 action that increased the use of the resources 

23 received credit; and 

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1 nized markets and vertically integrated mar2 kets, including options for the pricing. 

3 ‘‘(3) COMPLEMENTARY POLICIES.—The report 

4 under paragraph (1) shall examine the benefits and 

5 challenges of using complementary policies or stand6 ards, other than the standard established under this 

7 section, to provide effective incentives for using the 

8 additional clean energy resources. 

9 ‘‘(4) LEGISLATIVE RECOMMENDATIONS.—As 

10 part of the report under paragraph (1), the Sec11 retary may provide legislative recommendations for 

12 changes to the standard established under this sec13 tion or new complementary policies that would pro14 vide effective incentives for using the additional 

15 clean energy resources. 

16 ‘‘(o) EXCLUSIONS.—This section does not apply to an 

17 electric utility located in the State of Alaska or Hawaii. 

18 ‘‘(p) REGULATIONS.—Not later than 1 year after the 

19 date of enactment of this section, the Secretary shall pro20 mulgate regulations to implement this section. 

21 ‘‘SEC. 611. REPORT ON NATURAL GAS CONSERVATION. 

22 ‘‘Not later than 2 years after the date of enactment 

23 of this section, the Secretary shall submit to Congress a 

24 report that— 


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1 ‘‘(1) quantifies the losses of natural gas during 

2 the production and transportation of the natural 

3 gas; and 

4 ‘‘(2) makes recommendations, as appropriate, 

5 for programs and policies to promote conservation of 

6 natural gas for beneficial use.’’. 

Æ 


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